CALGARY – Like green shoots after a dark winter, an optimist might have called the sudden pickup in drilling rigs a sign that life is finally coming back to the hard-hit sector.

The number of rigs actively drilling in the United States and Canada jumped by 19 last week, to a total of 876 active rigs, according to the most recent data from Baker Hughes Inc.

Those additional rigs mark the third weekly increase in the North American drilling rig count in a month.

The green shoots have been stamped out

But optimism has a short shelf life in the oil industry these days. And now that oil prices have fallen from over US$60 a barrel last month back below US$50 again, analysts expect that activity to slow once more.

“I don’t think (oil) prices sub-US$50 are really high enough to justify a pickup in drilling in the U.S., if anything, I think they should be pulling back,” Scotiabank vice-president and commodity market specialist Patricia Mohr said Monday.

Mohr said the additional rigs are “one of the reasons why prices have moved down again,” as the market watches drilling rig numbers for signals of new oil supply in key shale plays in the U.S.

The West Texas Intermediate benchmark oil price closed at US$47.02 per barrel on Monday.

“There’s been a little pickup again in drilling in (Texas’) Permian basin but I do not think that’s a trend that’s going to stay with us, particularly given the drop in prices again in recent weeks,” Mohr said.

Indeed, analysts are now saying those signs of life, and the expectations of an uptick in activity going into the third and fourth quarters — expressed by major drillers like Halliburton Co., Baker Hughes and Schlumberger Ltd. — are disappearing.

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He added that the rig count would likely fall “in the coming weeks” as a result of the oil price plunge and as big and small oil companies pull back on spending.

Indeed, a recent report from Wood Mackenzie said global oil and gas producers have delayed US$200 billion in capital spending on major projects as the oil price rout has taken hold.

“The upstream industry is winding back its investment in big (not yet finalized) developments as fast as it can,” the report notes, adding that oil sands development in Canada and global offshore oil projects dominate the deferrals.

New oilsands mining projects require US$100 per barrel oil prices to earn a 10 per cent return on investment, while new steam-based projects require prices above US$60 per barrel.

“While the long-term value of the resource for companies such as Cenovus, Suncor and Shell is significant, we expect a lull in new project spending through to 2017, after which an increase in capital allocation and more FIDs (final investment decisions) will once again be on the cards,” the report notes.

2015 will see more ethnic groups within today’s cobbled-together countries successfully assert their autonomy, with the greatest changes occurring in the Middle East

My prediction: Big things based on lies, delusions and naiveté will fare poorly in 2015, continuing a trend of recent years that’s harrowing for the big-thing believers but welcome for most.

The global warming enterprise provides one example. Since 2008, I have been predicting that the warmists, whose cause at root is based on faith and sustained by deceit, will fail to make the case that carbon represents a danger to the planet. Although the elites have mostly bought the deceits — all ultimately resting on jigged computer models — the masses mostly have not, as seen in public opinion polls throughout the world. The public’s rejection of the global warming orthodoxy then led politicians to slash subsidies to renewables and to scrap plans for carbon taxes. Political parties that high-handedly ignored the public by pushing global warming measures, such as Canada’s Liberal Party in 2008 and Australia’s Labour government in 2013, went down to crushing defeats.

In 2015, I predict, the cause of global warming will continue to lose ground, even if, as expected, Pope Francis outs himself as a convert to the Church of Global Warming. Temperatures will again fail to behave as projected by the computer models, the public will again yawn at the faithful’s threats of the coming apocalypse and politicians will again pay lip service to global warming while kissing renewables subsidies goodbye.

As renewables lose momentum in 2015, fossil fuels will gain it. It can’t really be otherwise. If the glut we now see in oil and gas continues, the low prices that result will spur consumption. A rise in prices, on the other hand, would only further spur shale gas and oil development. Up or down, I predict, the environmental lobby loses the energy war, even if — should President Obama veto the Keystone XL Pipeline — it wins some battles.

Obama’s refusal would nevertheless be a hollow victory for environmentalists — Alberta oil will flow, Keystone or not. More significantly, environmentalism will increasingly seem a hollow pursuit by the generation about to inherit this earth: Today’s youth, having been force-fed an unrelenting diet of hype and fear, will have trouble stomaching more. Polls show youth’s appetite for things environmental has been waning. Look for this trend to continue.

The environmental mush that youth are rejecting originates largely from the mainstream media, which also dishes out pap when covering other politically correct issues. Herein lies much of the explanation for the collapse of the media’s authority — and thus of its audience. Among the cable news networks, CNN in 2014 logged the lowest audience in its history. Hard-left MSNBC got hit especially hard, with a 17% decline in prime time audience following a 29% decline in 2013. These ratings catastrophes contrast with those of Fox News, the only politically incorrect media outlet on global warming, on President Obama and on most other sensitive subjects. Fox — which scored the largest audience in cable news for 13 straight years now — bucked the disappearing-audience trend by increasing the size of its lucrative prime time audience in 2014, by scoring the 14 most popular shows, and by attracting more viewers than CNN and MSNBC combined.

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For 2015, I predict that Fox will again increase its audience on the strength of its straight-up reporting. Fox’s coverage of the Paris attack on the offices of Charlie Hebdo, whose cartoons of the Prophet Mohammed led to the slaughter by Islamist terrorists, provides one example of Fox’s journalistic integrity. Unlike many, perhaps most, major U.S. media outlets, Fox didn’t flinch from showing its audience the cartoons, even running a slide show on its website. In 2006, Fox was one of the few media outlets to air the Danish cartoons, and in 2007 it aired them again in a TV special.

Fox, along with every other major North American media outlet, does fall down in one major area of news reporting: It is not fair and balanced in coverage of the controversy over vaccine safety. Although prominent scientists dispute the public health authorities’ position on mass vaccinations, the mainstream media — which treats the safety of vaccines as a taboo subject — enforces a near-total blackout of dissenting views. I predict this taboo will persist in 2015, but that it will also fail to achieve its objective. Despite hearing only one side of the safety controversy — or perhaps because of it — many in the public will defy government health authorities and refuse to vaccinate their children, increasingly so.

This defiance will occur overwhelming among the well educated, urban demographic, and it will ironically serve the public health authorities. I predict that outbreaks of disease will continue to occur among highly vaccinated populations, giving the lie to the “herd immunity” theory advanced by the public health authorities, but also giving the health authorities a fig leaf — they will blame the outbreaks on the defiers.

One of the biggest things to happen over the last century involves one of the biggest delusions — that ethnic nations, being retrograde, are best controlled by larger political entities, whether multi-nation states or international bodies. Yet it is the multi-national structures that have collapsed.

The Ottoman, the Habsburg and the Russian empires all fell early last century, along with the League of Nations, followed by the collapse of the Soviet Empire and the unwinding of multi-ethnic or multi-nation states such as those in Czechoslovakia and Yugoslavia. The unwinding continues in Europe with the steady weakening of the European Union and the euro, and with Ukraine’s loss of Crimea; and with the increasing irrelevance of the United Nations.

I predict that 2015 will see more ethnic groups within today’s cobbled-together countries successfully assert their autonomy, with the greatest changes occurring in the Middle East, where we are seeing a de facto split up of Libya, Yemen, Iraq and Syria. With one exception, every country in the Middle East will be diminished politically, along with the region as a whole, because the shale oil and gas revolutions in the West have cost them their one source of influence — the ability to play the oil card.

The one exception is Israel, whose stature in the world — the media’s portrayal to the contrary — continues to grow and grow. Israel, in fact, has become an indispensable trading partner due to its high technology prowess, not least in the military field where its drones, Iron Dome, guided missile systems and other battle-tested wares are peerless. As one example, despite boycott threats over the Gaza War, Israeli exports to the UK increased 40 percent in 2014, setting a new record. In another, India, the world’s largest arms buyer, is negotiating a free trade agreement with Israel, which is increasingly meeting its military needs. In still another, China may soon edge out the U.S. in being the largest funder of joint ventures in Israel’s burgeoning high-tech industries. Israel’s indispensability has also broken the once solid anti-Israel Third World voting block at the UN, where two African countries recently sided with Israel to stop a Palestinian bid for statehood.

All told, I predict, free markets and free ideas and free people will prosper in 2015. This time next year, I’ll report back to you on how well these predictions held up.

NEW YORK — U.S. oil producers have been racing full-speed ahead to drill new shale wells in recent years, even in the face of lower oil prices. But new data suggests that the much-anticipated slowdown in shale country may have finally arrived.

Permits for new wells dropped 15 per cent across 12 major shale formations in October, according to exclusive information provided to Reuters by DrillingInfo, an industry data firm, offering the first sign of a slowdown in a drilling frenzy that has seen permits double since last November.

The Organization of Petroleum Exporting Countries last week agreed to maintain its production quota of 30 million-barrels-per-day, despite a 30 per cent drop in oil prices since June, triggering an additional 10 per cent decline. That move, many analysts believe, was squarely aimed at U.S. oil producers driving the country’s energy resurgence: can they continue drilling at the current pace if prices don’t rise?

“Currently, the market is focused on U.S. shale as the place where spending and production must be curtailed,” Roger Read, a Wells Fargo analyst, said in a note Friday. “There is little doubt, in our view, that lower oil and gas prices will result in lower spending and lower shale production in 2015 to 2017.”

A cutback of U.S. production could play into the hands of Saudi Arabia, which has suggested over the past few months that it is comfortable with much lower oil prices.

Most analysts predict U.S. oil producers can maintain their healthy production rates in the first half of 2015 — thanks in part to investments made months ago.

Some oil service companies have suggested that a slowdown might be held off, as they continue to buy key drilling components. But, the data suggests that production is likely to eventually succumb to lower prices.

“The first domino is the price, which causes other dominos to fall,” said Karr Ingham, an economist who compiles the Texas PetroIndex, an annual analysis of the state’s energy economy. One of the first tiles to drop: the number of permits issued, Ingham said.

Texas issued a record number of permits, 934, before dropping to 885 in October. The 885 is still more than double levels seen in the same month in 2010 when the shale revolution was just starting, but it shows a cooling off that hasn’t been seen to the same degree in the past two years.

A drop in the rig count is expected two to four months after a decline in permits — and production growth would likely start to slow six months later.

“This is a pull back from the acceleration. People are being careful,” said Allen Gilmer, chief executive officer of DrillingInfo. While permits have declined at other times, Gilmer says there is currently an early indication of a slowdown in the rig count.

DrillingInfo said for 10 shale formations, a permitting slowdown was noted in October. For one formation, data was not available, and for two, the Barnett shale in Texas and the Bakken in North Dakota, permits rose slightly.

The permitting slowdown was particularly pronounced in two Texas formations, the Permian Basin and Eagle Ford shale, which saw new permits decline by 13 and 22 per cent respectively.

THE STATE OF TEXAS

This year, shale has bolstered the Texas economy, with oil production in Texas up 23 per cent in August from a year earlier, according to the Texas Petro Index, released last month.

Oil and gas jobs are at an all-time high in the state, said Ed Longanecker, president of Texas Independent Producers & Royalty Owners Association — some 414,000 according to TIPRO, a figure that has risen for each of the past five years. Economic disruptions are expected as the price decline trickles down.

“As oil prices fall, there is going to be a response, and it will ultimately turn up in the numbers,” said Ingham.

Eagle Ford may be North America’s most prolific shale gas basin with more than 8,000 wells drilled in the region. By contrast its Mexican cousin, Burgos basin, just across the border, has barely seen any action. But that may soon change.

In a span of just two years since his 2012 election as Mexican president, Enrique Peña Nieto has swept aside state-owned Petróleos Mexicanos (Pemex) 76-year monopoly over the country’s oil and gas sector with a constitutional amendment and a string of new laws.

“The constitution was passed quickly and the secondary laws were passed with blinding speed, and the regulations are being implemented,” says Jay Park, a Calgary-based lawyer who has been advising Pemex since 2003. “Everybody I know in the Mexican government is working eighteen-hour days to get this done.”

While Mexico and Canada compete to supply heavy oil to U.S. Gulf Coast refineries, some Alberta companies are reportedly eying opportunities across the board in Mexico as North America’s last energy frontier opens up.

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Eddie Seal/BloombergWorkers guide a section of drill pipe into a rack after it was removed from a natural gas well being drilled in the Eagle Ford shale in Karnes County, Texas, U.S. Mexico has watched with envy the shale oil plays in the United States and Canada, especially Eagle Ford that now yields more than 1.5 million barrels of oil per day.

“Mexico is a unique opportunity right now,” says Peter Volk, general counsel and secretary at TSX-listed Pacific Rubiales Energy Corp. The company has been targeted by Mexico based-Alfa Group, which has taken a 19% stake in the company in recent weeks in a bid to leverage Pacific Rubiales’ expertise in heavy oil.

Mexico has watched with envy the shale oil plays in the United States and Canada, especially the Eagle Ford basin in Texas that now yields more than 1.5 million barrels of oil per day. Meanwhile, only 25 wells have been drilled on the Mexican side, even though the play is expected to contain 60 billion barrels of oil.

“Mexico is a virgin market,” says Oscar Lopez, E&Y’s Mexico City-based oil and gas leader. “There is opportunity to produce an additional market of the same size as we have today — 2.5 million bpd market.”

The International Energy Agency has more subdued projections for Mexico’s crude oil output, but that may change as the president pushes through with reforms. If all goes to plan, the country could attract US$350-billion in investments within a decade, according to some estimates.

While there is considerable resistance in Mexico to hang on to the family silver, Pemex is struggling to maintain production and also fund the government’s revenues. The company revenues make up 4.7% of Mexico’s GDP, and accounts for 30% to 40% of government revenues in taxes.

To appease critics, Mexico’s Energy Ministry (SENER) granted Pemex about 83% of the country’s proven and probable reserves to exploit on its own — known as the Round Zero allocation — when it announced the historic opening of the sector in August.

But that’s likely to encourage, not dissuade, American and Canadian companies.

“The biggest opportunity right now is Round Zero,” says Eduardo Rodriguez Jr., who founded Calgary-based Flatstone Energy, which advises Canadian clients on Mexican opportunities. “There are a number of opportunities for farm-outs and enhanced oil recovery projects that provide tangible opportunities for Canadian companies.”

The overall estimated investment for these projects could reach US$32.3-billion over a five- to 10-year time frame, according to Citibank estimates.

Pacific Rubiales has already taken that route, this month signing a deal with Pemex focused on exploration, deep-water projects, revitalization of mature fields, and heavy and extra-heavy oil.

“We feel that identifying and working with Mexican partners are really the only ways to properly enter the market,” Mr Volk said, noting that government-ownership of the oil and gas sector is embedded deep in the Mexican culture.

The key opportunities are in exploration and production, Mr. Rodriguez says. “It’s a bit like a first dance — who will start first, and Pacific Rubiales has taken the lead. Within next 12-24 months, we will see a number of other players going to Mexico.”

As part of the opening of the sector, SENER has also rushed to identify 169 production blocs, off and onshore, with total reserves of about 18 billion available for foreign investors in the so-called Round One bidding set for next year.

“All of these assets, though will require significant investment,” said Ernst & Young in a report, noting that the initial bid for the first round will likely come in November, with the tendering process starting early next year.
“The accelerated timetable gives companies less time to study the available opportunities, develop a detailed strategy for pursuing Mexican assets and prepare bids.”

International companies would also take a long hard look at the new jurisdiction at a time of when shareholders have little patience for marginal projects. But Mr. Park says many of the laws are being based on the “Canadian model” that would appeal to companies.

Canadian companies would also be mindful that their focus in Mexico may hurt them back home, as both countries compete to supply heavy oil to the U.S. Gulf Coast.

Mexican offshore heavy oil is a short tanker ride to the cluster of U.S. Gulf Coast refineries, while Canadian oil has to traverse through environmental opposition, get on barges, rails and choked pipelines across the length of the United States to get to the coast.

While Canadian oil is ascendant in the Gulf Coast in sharp contrast to receding supplies from Mexico, the country could emerge as a threat in future.

“I don’t think Mexico is a threat,” says EY’s Mr. Lopez. “The heavy oil requirements from the U.S. are extremely big. I see North America as an integrated oil-producing area, with Canada and Mexico complementing each other.”

For TransCanada Corp., Mexico’s infrastructure deficit is clearly an opportunity. The company has US$2.6-billion worth of natural gas investments in Mexico, comprising five pipelines, of which two are under construction.

“The gas infrastructure required in Mexico is growing significantly,” said Karl Johannson, president of TransCanada’s natural gas business. “Mexico is looking at the North America market and saying they want to be a bigger part of that. So they are building infrastructure from the centre of the country out north and connecting to the greater North American grid.”

The Calgary-based company also plans to bid for two power projects with a combined value of $1.5-billion, and is also eyeing opportunities to service the oil sector that may require as much as 15,000 kilometres of new pipelines.

“We have been talking to Pemex over a period of time,” Mr. Johannson said. “Right now, 100% of our business is in power and utilities in Mexico, but it’s not lost on us that Pemex is a pretty big market as well, and we would love to start doing some business with them.”

Security issues are often overplayed as well. “You have to be aware of security and build it into your plan, but it’s not something that we found have limited our ability to do business in communities,” Mr. Johannson said.

But there is opposition to development from some groups, including labour union leaders that have a vested interest in maintaining the status quo, and that may come to the fore as companies venture out on their own with Pemex’s cover.

“My feeling is that there is clearly a divide,” said Mr. Rodrigurez. “There is obviously conflict of interest from all the unions. They have a hand in the kitty — some of the union leaders are millionaires and have private jets — they continue to argue that oil is for the people.”

FRANKFURT — Germany’s Siemens has agreed to buy U.S. oilfield equipment maker Dresser-Rand for US$7.6 billion in cash, aiming to catch up with arch-rival General Electric in a booming U.S. shale gas market.

The acquisition, which ranks among the biggest in the history of the German industrial group, will strengthen Siemens’ position in the United States, its weakest region, and focus the group more tightly on its industrial customers.

Siemens embarked on a corporate overhaul in May dubbed “Vision 2020,” seeking to make up ground on more profitable competitors such as Switzerland’s ABB as well as U.S-based General Electric (GE), while reducing its exposure to more cyclical consumer businesses where it has had limited success.

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As part of that drive, the group said on Monday it had also agreed to sell its stake in household appliances joint venture BSH to partner Robert Bosch, bringing in 3 billion euros (US$3.9 billion) to help finance the Dresser-Rand deal.

“The Dresser-Rand offer is high but can be justified in our view due to the very good fit into Siemens target to strengthen the U.S. and oil & gas business,” DZ Bank analyst Jasko Terzic wrote in a research note.

Siemens’ U.S. energy business made 3.7 billion euros of revenues in its last fiscal year, compared with the roughly US$20 billion generated by GE’s U.S. operations in oil and gas alone.

Terzic said the deal put Dresser-Rand’s enterprise value (equity plus debt) at about 16 times earnings before interest, tax, depreciation and amortization (EBITDA), compared with around 8.5 times EBITDA for peers.

Reuters had reported on Sunday that the companies were nearing a deal.

Siemens has long coveted Dresser-Rand, but shrank in the past from making a formal bid, balking at its high valuation.

The German group appears to have been spurred into action by Swiss pump maker Sulzer AG, which had proposed an all-stock merger with Dresser-Rand, according to people familiar with the matter.

Sulzer said on Monday it had ended its talks with Dresser-Rand, but some analysts said there was still a chance of a rival emerging to challenge Siemens’ offer.

The Financial Times said on Friday GE was considering whether to make a bid for Dresser-Rand, citing people familiar with the matter.

One source close to the matter told Reuters that while GE had made contact with Dresser-Rand, it was unlikely to pursue a bid. Siemens lost out to GE in a bidding war for the energy business of France’s Alstom in June.

At 0945 GMT, Siemens shares were down 0.6%, slightly weaker than Europe’s blue-chip equities index. Sulzer shares were down 4.2%.

“PERFECT FIT”

Siemens said its US$83 per-share bid was unanimously supported by Dresser-Rand’s board of directors. The offer compares with a Friday closing price of US$79.91, which was up 27% over the past three months on takeover speculation.

A booming U.S. shale gas market has driven a surge in investment by energy companies, creating demand for the compressors and turbines made by companies such as Dresser-Rand.

Annual capital expenditure on oil, gas and coal has more than doubled in real terms since 2000 and surpassed US$950 billion in 2013, according to the International Energy Agency.

The Dresser-Rand deal will eclipse Siemens’ acquisitions of recent years. It bought Dade Behring for US$7 billion in 2007 under Kaeser’s predecessor Peter Loescher — now the chairman of Sulzer — in a deal that was widely criticized as overpriced.

Siemens filled another gap in its energy equipment portfolio earlier this year, buying small gas-turbine assets from Rolls-Royce for 950 million euros. CEO Kaeser indicated at the time that expansion in the United States was next on the agenda.

According to JP Morgan analysts, Siemens paid 12.5 times earnings before interest and tax (EBIT) for the Rolls-Royce assets, compared with the 20 times it is now offering to Dresser-Rand, underscoring the rich valuation for the deal.

Siemens said it was aiming for more than 150 million euros in annual synergies by 2019 from the Dresser-Rand transaction, which complements its business in turbo compressors, downstream and industrial applications as well as larger steam turbines.

The German group expects to close the deal by summer 2015, while it aims to wrap up the sale of its stake in BSH in first half of 2015, ending a more than 45 year alliance in household appliances.

Siemens has had a checkered history in consumer markets. It sold its mobile phone business last decade, which later went bust. It exited the Fujitsu Siemens Computers joint venture in 2009, and spun off light-bulb maker Osram in 2013.

BSH will pay out 250 million euros to each of its owners, Bosch and Siemens, before the transaction is completed.

Bosch, a Stuttgart-based automotive supplier, said it was on the lookout for more acquisitions after buying the rest of BSH.
Analysts said Sulzer was also likely to still target deals, given its net cash of about 800 million Swiss francs.

The U.S. oil boom has put European refineries out of business and undercut West African crude suppliers. Now domestic drillers threaten to roil Asian markets and challenge producers in the Middle East and South America.

Fifteen European refineries have closed in the past five years, with a 16th due to shut this year, the International Energy Agency said, as the U.S. went from depending on fuel from Europe to being a major exporter to the region. Nigeria, which used to send the equivalent of a dozen supertankers of crude a month to the U.S., now ships fewer than three, according to the U.S. Energy Information Administration. And cheap oil from the Rocky Mountains, where output has grown 31% since 2011, will soon allow West Coast companies to cut back on imports of pricier grades from Saudi Arabia and Venezuela that they process for customers in Asia, the world’s fastest-growing market.

“I don’t really think anyone saw this coming,” said Steve Sawyer, an analyst with FACTS Global Energy in London. “The U.S. shale boom happened much faster than people thought. We’re in the middle of a new game. There’s nothing in the past that predicts what the future will be.”

Advances in extracting oil from shale rock drove a 39% jump in U.S. production since 2011, the steepest rise in history, and will boost output to a 28-year high this year, according to the EIA. While drilling in shale is more expensive than other methods and poses environmental challenges, the prospect of a growing supply is encouraging analysts to predict a more energy-independent nation.

With U.S. exports of gasoline and other refined products hitting a record last month and the country on pace to become the world’s largest oil producer by 2015, five years faster than the IEA’s earlier predictions, industry advocates such as Senator Lisa Murkowski of Alaska are calling for an end to 39- year-old restrictions on U.S. crude exports.

In a measure of just how quickly the oil market has changed, President Barack Obama unveiled in March 2011 a goal considered so outrageous that correspondent Christopher Mims wrote on the environmental news website Grist that it could be accomplished only by “an economic crash bigger than any ever seen in U.S. history, or perhaps an alien race forcing all of us to take to our bicycles.” Obama said that by 2025 the U.S. would cut crude imports by one-third.

It didn’t take 14 years. It took less than three.

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The country is so flush with crude that imports are plunging and drillers are challenging export limits imposed after the 1973 Arab oil embargo. Murkowski, the top Republican on the Senate Energy Committee, called on Obama yesterday to end restrictions and vowed to introduce legislation if he doesn’t.

Easing controls would have been unthinkable just three years ago, when uprisings in Arab countries such as Libya pushed crude prices over US$100, said Philip Verleger, a former director of the office of energy policy at the Treasury Department and founder of the Aspen, Colorado-based consultant PKVerleger LLC.

The boom has been led by drilling in the Permian Basin in West Texas and the oil-rich Bakken shale, which stretches from North Dakota into Montana and Canada.

North Dakota and Texas have more than doubled crude output since Obama’s 2011 speech, with Texas pumping more than Iran, according to the EIA, the statistical arm of the U.S. Energy Department, and a Bloomberg survey of producers, oil companies and analysts.

Matthew Staver/Bloomberg files

Drilling is spreading in emerging oil fields in the Rocky Mountain region such as the Niobrara in Colorado and the Bone Springs in New Mexico and spurring a revival of crude extraction around Wyoming’s Teapot Dome formation, home of the first U.S. reserves and the namesake of a 20th century political scandal. Colorado’s production jumped 17% in the first 10 months of 2013, Wyoming rose 16% and New Mexico added 10%, according to the EIA.

A record amount of crude is already riding the rails from oil fields in North Dakota, Colorado and New Mexico to California’s fuel makers, according to the California Energy Commission. Companies looking to ship even more include Tesoro Corp., Valero Energy Corp. and Plains All American Pipeline LP, which are planning to build train terminals in California and Washington state, according to company statements and regulatory filings. Plans are awaiting permits or in the planning stages to handle capacity roughly equal to the amount of crude sent to the region by Saudi Arabia.

If the railway networks on the U.S. West Coast are completed, the region’s refiners will be able to use domestic crude supplies to boost exports to meet rising needs in Asia, where demand for new cars, electricity and air conditioning is boosting energy consumption. China, already the world’s largest importer, will rely increasingly on crude from the Middle East and refined fuels from the U.S. to meet its consumers’ growing demand.

An increase in the number of U.S. cargoes to Asia might force Saudi Arabia to cut its output to head off a worldwide glut, Verleger said. As the de facto leader of the Organization of Petroleum Exporting Countries, the kingdom is monitoring signs of potential oversupply as Iraq and Libya try to boost output and Iran increases exports as international sanctions are loosened, he said.

“It’s another outlet for North American oil products and means more supply for the rest of the world,” said Andy Lipow, president of Lipow Oil Associates LLC, an energy consultant in Houston. “The West Coast is behind the rest of America as far as getting crude by rail. It will increase supply and help the consumer.”

Hydraulic Fracturing

The U.S. gains were made possible by innovations in horizontal drilling and hydraulic fracturing, or fracking, that have unlocked fuel trapped in underground rock. The technology allows producers to bore horizontally, then use explosives and a high-pressure stream of water, sand and chemicals to blast open fractures that free the oil.

The process comes with environmental risks. A 2011 U.S. government report found fracking chemicals in groundwater in Pavillion, Wyoming, and in June, 47 people died when an unmanned train carrying Bakken crude derailed and exploded in Lac Megantic, Quebec. Crude from the Bakken may be more flammable and more dangerous to ship than other types of oil, the U.S. Transportation Department said Jan. 2.

Fracking is also more expensive than traditional extraction. Drilling a horizontal shale well in the Bakken can cost 10 to 20 times what a vertical well might cost, according to Austin, Texas-based Drillinginfo Inc. Production from shale wells declines by 60% to 70% in the first year, while output from traditional wells diminishes by as much as 55% in two years before flattening out, according to Drillinginfo.

One reason the U.S. still depends so much on imports is that demand continues to outstrip domestic supply. Another reason is the quality of crude its refineries can handle. Many of them performed expensive upgrades in the past decade so they could process oil from overseas that was more difficult to turn into transportation fuel.

David Paul Morris/BloombergGasoline users benefit from the surge in U.S. production.

Gasoline users and diplomats benefit from the surge in U.S. production. While the 2011 Libyan uprising had U.S. consumers paying almost US$4 a gallon for gasoline, pump prices declined 1.3% last year and averaged US$3.314 a gallon on Jan. 6, according to AAA, the largest U.S. motoring organization. That was even after sanctions cut off more than 1 million barrels a day of Iranian oil exports. Starved of their primary source of cash, the Islamic republic’s leaders in November reached an agreement to curb its nuclear program.

“It took time to realize how significant this transformation was going to be,” said Jason Bordoff, who was an energy adviser to the National Security Council and helped draft Obama’s 2011 speech. “We were able to impose pain on Iran without imposing pain on ourselves.”

Rail Routes

New rail routes and pipelines are carrying increasing supplies of crude from North Dakota, Oklahoma and elsewhere to refiners in New Jersey, Louisiana, Texas and Pennsylvania. They are in turn sending cargoes of diesel to London, Rotterdam and Antwerp, Belgium. U.S. fuel exports to the Netherlands, a major import hub for the region, reached a record in September, according to the EIA.

The one-two punch of declining crude imports followed by rising fuel exports hit the refining industry in Europe and the U.K. particularly hard. That’s because refiners outside North America typically buy oil based on the price of Brent crude, a North Sea grade that last year cost an average of almost US$11 a barrel more than West Texas Intermediate, the U.S. benchmark.

WTI futures on the New York Mercantile Exchange traded at US$93.77 a barrel today, a 13% discount to the Brent price of US$107.45 on ICE Futures Europe in London. The spread widened to a record US$27.88 a barrel in October 2011.

“When historians write this story 10 or 20 years from now, they are going to look at a very different U.S.,” said Verleger, the former Treasury Department official. “Everything has changed.”

The U.S. will surpass Russia as the world’s top oil producer by 2015, and be close to energy self- sufficiency in the next two decades, amid booming output from shale formations, the International Energy Agency said.

Crude prices will advance to US$128 a barrel by 2035 with a 16% increase in consumption, supporting the development of so-called tight oil in the U.S. and a tripling in output from Brazil, the IEA said Tuesday in its annual World Energy Outlook. The role of the Organization of Petroleum Exporting Countries will recover in the middle of the next decade as other nations struggle to repeat North America’s success with exploiting shale deposits, the agency predicted.

“The United States moves steadily towards meeting all of its energy needs from domestic resources by 2035,” the Paris-based advisor to 28 energy-consuming nations said Tuesday. “But this does not mean that the world is on the cusp of a new era of oil abundance. Light, tight oil shakes the next 10 years, but leaves the longer term unstirred.”

Soaring shale output in the U.S. is helping the world’s largest oil consumer achieve its highest level of energy independence in two decades, cushioning it against disruptions in Africa and the Middle East. The boom threatens revenues for OPEC’s 12 members, whose production is at its lowest in two years amid political unrest in Libya and theft in Nigeria.

The U.S. will overtake Russia, currently the biggest oil producer, in 2015 as it taps rock and shale layers in North Dakota and Texas with the use of horizontal drilling and hydraulic fracturing, according to the report. The nation’s output will plateau after 2020 and it will lose its top ranking at the beginning of the 2030s, the report said.

“We do not expect this trend will continue after 2020s,” Fatih Birol, the agency’s chief economist, said in London today. “It will come to a plateau and decline as a result of the limited resource base of light tight oil.”

U.S. crude production rose to 7.896 million barrels a day in the week ended Oct. 18, the most since March 1989, according to the Energy Information Administration. West Texas Intermediate futures dropped as much as 83 cents to US$94.31 a barrel in trading Tuesday on the New York Mercantile Exchange and was US$94.83 as of 11:36 a.m. in London.

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Global oil demand will expand by 14 million barrels to average 101 million a day in 2035, according to the IEA report. The share of conventional crude will drop to 65 million barrels by the end of the period because of growth in unconventional supplies, the IEA said without providing current data.

The concentration in global oil trade will continue to shift to the Asia-Pacific from the Atlantic Basin, as China is on the verge of becoming the world’s biggest oil importer, the report showed. India will displace China as the biggest driver of energy demand growth after 2020, the IEA said.

Expanding refinery capacity in Asia and the Middle East along with reduced demand in many developed nations is intensifying the pressure for plants to close, the agency said.

The IEA estimates that almost 10 million barrels a day of oil processing capacity is “at risk” by 2035, with refineries in Europe in particular the most vulnerable, it said. This equates to about 10% of current global capacity, based on data compiled by Bloomberg on more than 700 sites worldwide.

Brazil will triple output to 6 million barrels a day by 2035 as it exploits deep-water reserves, an expansion that will account for one-third of the increase in global production and make the nation the world’s sixth-largest oil producer, according to the agency.

Regain Importance

While North American shale, coupled with rising production in Brazil and global supplies of natural gas liquids, will dominate output growth over the next 10 years, OPEC, and its Middle Eastern members in particular, will regain importance after that as supplies from outside the organization falter, according to the report. OPEC pumps about 40% of global oil supplies.

“The Middle East, the only large source of low-cost oil, remains at the center of the longer-term outlook,” the agency said.

OPEC’s members are Algeria, Angola, Ecuador, Iran, Iraq, Kuwait, Libya, Nigeria, Qatar, Saudi Arabia, the United Arab Emirates and Venezuela. It will next meet to review production targets on Dec. 4 in Vienna.

More than half of the 790 billion barrels the world will need to produce by 2035 is needed to compensate for declining output from mature deposits, the agency said. Output declines at a rate of 6% a year at conventional oil fields once they reach peak production, according to the report.

Oil production in North Dakota topped 800,000 barrels per day for the first time ever in May, preliminary data from the state regulator showed on Monday, as the number of rigs pumping crude in the state hit an all-time peak.

The state’s Mineral Resources Department said output in May was up 2% – or 16,277 barrels per day (bpd) – hitting a record 810,129 bpd even as record rainfall for the month impeded new drilling.

Oil production in North Dakota has soared five-fold since 2008 as developments in horizontal drilling and hydraulic fracturing – commonly referred to as “fracking” – have allowed producers to tap the giant Bakken shale formation, transforming the state into the second largest oil producer after Texas.

There are now a record 8,915 producing wells in North Dakota, the Mineral Resources Department said, though the number of rigs drilling new wells in May increased by only one from April to 187, which was down 14 percent from the record level of 218 in the same month last year.

Well completions, whereby wells undergo hydraulic fracturing and are made ready to pump oil, rose by 10 in the month to 143.

“That number of completions is above the threshold needed to maintain production so oil production rate rose,” the department said in a statement.

“Load restrictions have remained in place longer than ever before because May 2013 was the wettest on record.”

The department said in April it expected production to accelerate only after May as rough weather and road restrictions in the months before limited activity. The state forecasts production of 850,000 bpd by early 2014.

Where others see a U.S. energy revolution of cheap and abundant fuel, David Hughes sees a short-term bubble that will bring higher economic and environmental costs.

The Canadian geoscientist, founder of the consultancy Global Sustainability Research, is part of a movement pushing back against conventional wisdom that the U.S. is on the verge of energy independence amid surging oil output and a 100-year supply of natural gas.

Projections of 2,384 trillion cubic feet of gas supplies provide false confidence because they don’t adequately account for the cost of production declines of as much as 47 percent a year that come with drilling in shale, Hughes said.

While President Barack Obama endorses the use of more gas as a power-plant fuel and the U.S. considers expanding gas exports to exploit the current glut, shale skeptics such as Hughes and Bill Powers, a director of Calgary-based oil and gas producer Arsenal Energy Inc., warn that consumers and industry will feel the pain of rising prices when supplies fall short of estimates they say are based on a mistaken belief that the torrid growth seen in the past five years will continue.

“Human nature doesn’t change, and we extrapolate recent trends far into the future even if those trends are woefully unsustainable,” said Powers, author of “Cold, Hungry and in the Dark: Exploding the Natural Gas Supply Myth.” Advances in shale-gas technology won’t continue forever, he said, “and we’re probably seeing them reach their maximum potential as far as production growth goes.”

Fast Fade

Wells drilled into the hard rock of shale produce a burst of oil and gas after being hydraulically fractured — a technique that cracks the rock to release hydrocarbons. The flow rapidly diminishes as gas must migrate farther through the rock to reach the fracturing site where it can enter the well. To counter the declines, companies drill more wells, longer wells, and intensify the fracking process, all of which can raise costs.

About $42 billion must be spent every year just to offset decline rates in shale gas wells that generated revenue of about $33 billion in 2012, Hughes estimated in a report earlier this year for the Post Carbon Institute, which advocates options for a more sustainable world. Proceeds from higher-priced petroleum liquids contained in the most lucrative wells have helped offset the deficit for now, though the industry faces higher costs from increasingly uneconomic wells as the best prospects are exhausted, he said.

Wrong Assumptions

To Hughes, cheap gas and abundant gas are “mutually exclusive” in the long term. Instead of providing a reason to accelerate fossil fuel use, new supplies of crude and gas from shale fields just give the U.S. more time to develop alternative energy solutions, he said.

According to Arthur Berman, a Houston-area geologist and director of Labyrinth Consulting Services, basing U.S. policy on what he sees as overly optimistic supply and low-price projections is foolish.

Shale production mushroomed in the past decade as producers expanded the use of horizontal drilling and hydraulic fracturing — fracking — to wrest oil and gas from previously impermeable rock. Gas output in the U.S. climbed 25 percent from 2007 to a record last year, according to U.S. Energy Information Administration data.

In April, the Potential Gas Committee, which issues a biennial report with support from the Colorado School of Mines, said the U.S. had a technically recoverable resource base of 2,384 trillion cubic feet of gas at the end of 2012, while other estimates claim the resource can last 100 years, the committee said on its website.

The surge in supplies pushed prices down to a decade low last year below $2 per million British thermal units — a price that only added to gas’s appeal as consumers and industry switched to the cheaper fuel to save money.

T. Boone Pickens, the billionaire who advocates a plan to replace imported oil with domestic natural gas, says gas should become the preferred fuel in vehicles. At the same time, the continental U.S. may see as many as six gas export projects built, sending offshore as much as 10 billion cubic feet a day of gas by the end of 2022, according to one prospective exporter, Freeport LNG Development LP, in an interview last month.

Decline rates cited by the skeptics already have been incorporated into many supply estimates, said Erica Bowman, chief economist at America’s Natural Gas Alliance, an industry group whose members include Chesapeake Energy Corp., Apache Corp. and Devon Energy Corp.

Affordable Prices

“We have a very large, abundant supply of natural gas, and we have it at prices that are very affordable, and honestly, we have so much supply that we need the demand outlets,” said Bowman.

Skepticism about shale’s potential was raised as early as 2009, when Berman drew rebukes from Chesapeake and Devon for his work questioning the projections for shale gas as overly optimistic. Berman, who was among the first to point out the steep declines in production after a well is drilled, continues to sound the warning bell for policy makers about what he sees as unrealistic estimates.

“They’ve got sugar plum fairies dancing in their heads about this infinite supply and how much money we’re going to make and the net for the U.S. economy,” Berman said in a July 2 phone interview.

Decline Rates

Wells drilled before 2012 in the top U.S. shale gas areas indicate an average field decline of 37 percent a year, according to data compiled by Hughes. That includes 47 percent in the Haynesville Shale, which includes part of Louisiana, and 29 percent in Pennsylvania’s Marcellus Shale.

Gas prices rose this year to more than $4 per million Btu before subsiding to a current level of about $3.60. As lower- quality wells raise the cost of production and tighten supplies, gas may rise to $6.50 in 2018 and to $8 or more in 2022, with spikes into double-digit prices possible within five years, Hughes says. Powers, the author, also said gas prices may surge into the double digits in the future.

Jeremy Grantham, who co-founded global investment manager GMO LLC, is another sharing that bullish view, estimating in an April report that gas prices may triple from last year’s low in five years, to about $6 or $7.

Gas remains far from parity with oil on an energy- equivalent basis, Pickens said, which would require gas prices of about $16 per million British thermal units when oil is at $100 a barrel.

“I’ll never see $16 natural gas in my lifetime,” Pickens, 85, who scoffs at the pessimism of skeptics, said in a July 12 interview.

Cheap Production

ICF International, an industry consultancy, estimated in a report that the U.S. and Canada have 1,500 trillion cubic feet of gas that can be developed at a cost of $5 or less per million Btu. That includes about 800 trillion cubic feet of shale gas, ICF said.

For now, low prices have flattened U.S. gas production as producers divert their resources to drilling for more profitable oil. Yet output still is “kind of hanging in there,” said David Pursell, a managing director at Tudor Pickering Holt & Co. in Houston.

Daily U.S. gas output is forecast to be 70 billion cubic feet in 2013 and 70.4 billion cubic feet next year, compared with 69.2 billion in 2012, according to a July 9 outlook from the U.S. Energy Information Administration, or EIA.

Crude Growth

The expected growth rate is stronger for crude, which is trading for more than $100 a barrel in New York. The EIA forecasts the U.S. daily output will average 7.3 million barrels this year and 8.1 million barrels in 2014, compared with 6.5 million in 2012.

Hughes said U.S. policy priorities should include measures to reduce energy consumption in transportation, such as encouraging the building of higher-density communities that require shorter commutes. That would make renewable fuel options such as wind and solar more viable to help supplement oil and gas.

Gas prices at less than $6 won’t generate as much production as people expect, he said.

“At those prices, gas production will decline in the U.S.,” Hughes said. Production would grow at higher prices, but at a significant cost to the economy. The problem with the hype, Hughes said, is that it predicts we’ll have both: “cheap and abundant.”

U.S. oil production grew faster than almost all other major energy players in the world last year, but some analysts believe the industry will not be able to maintain its blistering growth.

American oil production led by the Bakken and Eagle Ford plays hit 8.9 million barrels per day last year, 13.9% higher than 2011 – and the highest ever in the country’s history, according to BP’s benchmark annual Statistical Review of World Energy.

“On the supply side, the most noticeable phenomenon remains the American shale revolution,” Bob Dudley, BP’s group chief executive officer said in the report. “In 2012, the U.S. recorded the largest oil and natural gas production increases in the world, and saw the largest gain in oil production in its history.”

Only Libyan production grew faster in 2012 at 215%, after a bloody civil war in 2011 completely shut down production in the Middle East country.

Canadian production also grew strongly at 6.8% to average around 3.7 million bpd last year.

While many key producers and exporters collectively cranked up production by 2.2% in 2012, it was not met by a corresponding rise in demand, which grew by a mere 0.9%.

“The year 2012 saw a slowdown in the growth of energy consumption globally, partly as a result of the economic slowdown but also because individuals and businesses have responded to high prices by becoming more efficient in their use of energy,” Mr. Dudley said.

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The U.S., which remains the world’s largest consumer of oil, saw a 2.3% contraction in consumption. Canadian energy consumption also fell nearly one per cent last year. The European Union also saw a dramatic 4.6% drop in crude consumption as well.

American energy producers also kept the foot on the pedal in natural gas production, rising 4.7% to a record 681.4 billion cubic metres—more than a fifth of global natural gas production.

Across the border, however, Canadian producers mothballed gas rigs and cut production by 2.3% due to poor export prospects, pricing and domestic consumption.

Coal also managed to grow both in terms of production and consumption, despite its much-publicized displacement by natural gas. Coal production grew 2%, while demand grew a tad faster at 2.5%, according to BP data.

At the other end of the energy spectrum, renewable energy consumption galloped ahead, rising 15.2%, led by solar demand, which grew 58% ruing the year.

‘BEST IS BEHIND US‘

While the latest BP survey reiterates American oil renaissance, some observers are calling for a more sober projection of future American crude production.

AllianceBernstein, a Wall Street research house, believes the current marginal cost of crude in the U.S. stands at around US$95 per barrel, which makes production of new barrels especially vulnerable to a collapse in price.

At the same time, well production rates are falling in dominant plays of Bakken and Eagle Ford, and new plays have been disappointing, suggesting that “the best is behind us”, the research house believes.

“Wells with peak production rates of 1,000 barrels or more are becoming increasingly scarce,” said Scott Gruber, analyst at AllianceBernstein. “Amazingly, despite having another 20,000 drilling locations remaining, or ten years of drilling inventory at the current development pace, the Bakken is already showing its age.”

Bob Brackett, senior analyst at the firm, sees watershed moment coming in oil, “and that inflection point is the day or the month or the time where people realize that the rate of growth in U.S. liquid production is slowing.”

“We see U.S. liquid production rising year after year for several more years. What we don’t expect and what we believe will come to pass – we don’t expect the million barrels a day of oil growth that we saw year on year at the end of last year.”

Bart Demosky, chief financial officer at Suncor Energy Corp. also believes that while tight oil is here to stay, the United States will remain a larger importer of crude oil.

“There is no consensus what the ultimate [U.S.] production is going to be,” Mr. Demosky told an audience at a conference in Montreal on Tuesday.

“The bulls will say technology will continue to advance and grow rapidly. The bear says the costs are high, technology can’t solve everything, and the wells are going into rapid decline. No matter what happens there, there is going to be a place for Alberta’s oil sands in the mix.”

U.S. drillers that set up rigs amid the rolling farmland of eastern Ohio on projections underground shale held US$500-billion of oil are packing up.

Four of the biggest stakeholders in untapped deposits known as the Utica Shale have put up all or part of their acreage for sale, as prices fall by a third in some cases. Chesapeake Energy Corp. of Oklahoma City, the biggest U.S. shale lease owner, last week offered up 94,200 acres (38,121 hectares). EnerVest Ltd. and Devon Energy Corp. are selling as early results show lower production than their predictions.

“The results were somewhat disappointing,” said Philip Weiss, an analyst with Argus Research in New York. Early data show “it’s not as good as we thought it was going to be.”

The flip-flop underscores the difficulties faced by even experienced drillers around the world in tapping the sedimentary rock. In California, Occidental Petroleum Corp. was stymied by the Monterey Shale’s fault-riddled terrain. In Poland, Exxon Mobil Corp. stopped drilling because shale output was minimal. China’s failures with shale gas drove producers Cnooc Ltd. and China Petrochemical Corp. to seek expertise in North America.

In Ohio’s Utica formation, which runs eastward as far as New York, drillers frequently found the rock too dense and underground pressures insufficient to produce oil.

The rush to buy acreage has reversed.

The Utica saw one deal valued at more than US$50-million in the fourth quarter of 2012, compared with seven in North Dakota’s more productive Bakken Shale and six in Texas’ Eagle Ford Shale, according to the accounting firm PricewaterhouseCoopers LLP.

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By 2017, the Utica should produce a daily average of 200,000 barrels of oil, Wood Mackenzie Ltd. estimated. The Eagle Ford by then will be producing 1.15 million barrels a day, almost six times more.

“People started to realize that, you know what, maybe the oil window of the play is not all it’s cracked up to be,” said Jonathan Garrett, an analyst at Wood Mackenzie who has studied the Utica.

Utica acreage can fetch about US$1,000 to US$8,000 an acre, Garrett said. In the Eagle Ford, which produced about 374,000 barrels of oil a day in January, acreage can cost about US$5,000 to more than US$36,000 an acre, he said.

Gulfport Energy Corp. paid US$10,000 apiece for 22,000 net acres in Utica in February, compared with US$15,000 an acre Total SA spent on a joint venture with Chesapeake in January 2012.

The global exploration and production industry, which Cowen Group Inc. estimates will spend US$645-billion this year, is learning how hard it is to transfer practices and expectations from one shale formation to another and replicate the success of the top fields, such as the Eagle Ford.

Shale Spotlight

The Utica grabbed the U.S. shale spotlight in 2011 when the Ohio Department of Natural Resources estimated it held 5.5 billion barrels of recoverable oil reserves — equivalent to more than twice Yemen’s proven resource and valued at about US$488-billion at Monday’s US$88.71-a-barrel U.S. oil price.

Chesapeake had boasted Utica would outperform the Eagle Ford. EnerVest, the biggest gas producer in Ohio, had said the Utica would bring jobs and new industry to the state. EnerVest in the past year has tried to sell acreage there and no buyers have emerged.

EnerVest is selling out of the Utica because oil production doesn’t fit its low-cost business model, Mark Houser, chief executive officer of EV Energy Partners LP, said in an interview. EV Energy is a master-limited partnership controlled by Houston-based EnerVest.

Code Cracking

Going for natural gas is another story. Some areas of the Utica were found to be rich in gas liquids, though only a minority of companies are positioned to benefit. They include Gulfport of Oklahoma City and Denver-based PDC Energy Inc.

Chesapeake has decided to leave it to other companies to crack “the code” of the Utica’s oil prospects after the company found it wasn’t worth trying any longer, Senior Vice President Jeff Mobley said in December at an industry financial conference. Since September, Chesapeake has been seeking a partner to share ownership and costs in the Utica.

Devon, also based in Oklahoma City, decided to sell its 157,000 net acres in the Utica so it can concentrate on more profitable plays, said Chip Minty, a spokesman.

PDC, another Utica explorer, dropped its effort to find a partner when it couldn’t get a high enough bid for the stake it was offering, and in September decided to go it alone.

Better Fracturing

Early drilling results showed the oil portion of the Utica isn’t as porous as some other shale formations and is shallower than its gas-filled areas, meaning it’s harder to get oil to flow through the rock, and there’s less natural pressure to help force it out, said Jerry James, president of Artex Oil Co. in Marietta, Ohio.

Operators are looking for better ways to fracture their oil wells, and discussing whether to use pumps to get crude to the surface, James said.

“Some of the oil window is going to work, it’s just going to take a while,” James said.

The Utica has the potential to be one of PDC’s top performers, based on the company’s recent results, Vice President Scott Reasoner said in an e-mail.

Much still depends on the construction of processing units and pipelines to provide a route to market for Utica production. The pace of drilling has been hindered by a lack of infrastructure that may require a US$30-billion investment over three years to build out, said Jack Lafield, CEO of Dallas-based pipeline operator Caiman Energy LLC.

The number of drilling rigs in the Utica has risen year over year, indicating that producers still see value in the field despite the lack of oil, said Jeff Daniels, a professor at Ohio State University who heads the school’s Subsurface Energy Resource Center. The problem with oil production may be solved with new technology.

“We have a lot to learn about producing from these shales,” Daniels said.

Shale prospectors in Australia’s vast Outback are homing in on oil as the lucrative prize that is easier and cheaper to exploit than gas.

Initial hopes had been to replicate a U.S. shale gas boom, but the economics of targeting oil rather than gas derived from shale formations, once considered a mere by-product, look increasingly compelling in Australia.

Gas, with no large domestic customer base, needs costly pipelines and plants to chill the fuel for export. In contrast, oil can be trucked to rail lines and ports, so is potentially more immediately profitable, and large finds could reverse more than a decade of declining Australian output.

Australia also already has sufficient conventional and coal seam gas reserves to feed enough liquefied natural gas projects to make it the biggest LNG exporter by the end of the decade, so a U.S. shale gas boom that has freed up abundant, previously unrecoverable reserves and brought prices down 40 percent since November 2008 looks a less attractive development model.

“Oil is easy,” said Peter Bond, the managing director of Linc Energy, which recently said it could be sitting on resources that could rival the Bakken shale, one of the main drivers of the United States’ surge in oil production.

“It’s $5 to $6 per barrel to get it to a road train from where you are to a port, with a $100 plus price per barrel of oil, that’s not hard to do.”

Australia’s potential as a big shale gas or shale oil producer is not yet clear, with large-scale commercial production up to 10 years away by the industry’s own estimates. That has not stopped some optimistic claims of the potential from emerging, with Linc Energy saying its shale acreage may hold 233 billion barrels of oil equivalent, almost as much as Saudi Arabia.

The company estimates, however, only a fraction of that – about 3.5 billion barrels – is likely to be recoverable.

Still, it’s hard for developers like Linc Energy to ignore that U.S. shale discoveries may help lift oil production there to its highest level in 26 years in 2014.

New Standard Energy and Buru Energy have both said they are looking for oil rather than gas in the Canning Basin, a desert area in northwestern Australia with no energy infrastructure.

Late in 2012, New Standard abandoned the first well drilled at its Goldwyer project in the Canning Basin after finding gas without the liquids that would make development profitable.

“If you’ve got liquids associated with your gas, the economics of developing that field are significantly enhanced. The gas becomes more of a byproduct than a mainstream revenue driver,” Sam Willis, director of New Standard, said in a telephone interview.

Oil output in Australia was 484,000 barrels per day (bpd) in 2011, down 36 percent from 2001, according to data from the BP Statistical Review of World Energy. The country is a net importer and its output makes up just 0.5 percent of the world’s total oil production.

NEED FOR EXPORTS

While oil is the focus for firms exploring in the furthest reaches of the Outback, those exploring shale reserves near existing gas pipelines and export infrastructure have more reason to be hopeful about gas.

Australia’s government says shale could double the country’s gas reserves and the sector has attracted the interest of some of the world’s top oil companies. Chevron Corp was the latest to jump in with a $349 million investment in February.

Others that have farmed into Australian shale plays include ConocoPhillips, Total, Japan’s Mitsubishi Corp and India’s Bharat Petroleum. Australia’s richest person, iron ore magnate Gina Rinehart, has also entered the business, buying into Lakes Oil early this year.

Big energy firms are getting involved now to avoid the risk of having to pay a lot more for acreage should reserves prove up and production begin in earnest.

Australia is already well on its way to becoming the world’s top LNG exporter, with $190 billion of projects under development. Those projects rely on gas from conventional fields or from coal beds, rather than from shale.

So many plants being built at the same time has led to billions of dollars of cost overruns, so for now developers have little appetite for more export projects – but some would welcome a top-up in gas supplies from nearby shale fields.

“In the current environment, where you have all the projects being built that are getting hamstrung by their costs, it’s not a real hotbed of development for further export projects to take shale out,” said Noelle Leonard, an analyst with FACTSGlobal Energy in Perth.

REPLACE COAL SEAM GAS

Australia’s relatively small population means there is a limited domestic appetite for more gas, so producers need access to the export market to make gas development worthwhile.

“If there wasn’t the view of an export market going forward, we would not be drilling these wells,” said James Baulderstone, Santos’ vice president of Eastern Australia, after the firm brought its first commercial shale gas online.

Santos plans to feed its shale gas into nearby pipelines linked to its LNG export plant on the east coast which is due to start shipments in 2015. The shale gas will likely help compensate for Santos’ shortage of coal seam gas to fuel its LNG plant in eastern Australia.

Some other shale gas explorers, such as Beach Energy , are also counting on shale as a replacement for the disappointing performance of coal seam gas.

“Coal seam gas has not quite lived up to expectations, so everyone is watching this shale unconventional play quite closely,” Chris Jamieson, general manager of investor relations at Beach Energy in Adelaide, said.

GettyAn Iranian oil refinery. If prices drop, Iran would need to scale back
its nefarious activities.

Shale oil boom means security

To fight jihadists, foreign policy hawks have long promoted global warming legislation: If carbon taxes and conservation programs can get us off Middle Eastern oil, the hawks reasoned, oil prices will drop as demand drops and money for terrorist attacks will dry up. Out came global warming legislation touting its benefit for national security, such as the Climate Security Act of 2008, which promised deep cuts to America’s dependence on Middle East oil by 2050.

Those hawks should reconsider. Global-warming legislation has emerged as the single biggest threat to the West’s energy security and the single biggest boon to most of the West’s geopolitical foes. The game changer is shale oil. The U.S. has so much of it that Citigroup, in a report released earlier this month, states that in five years the U.S. could eliminate all oil imports from the Middle East and other hostile suppliers and become a net energy exporter. The U.S. has already halved its oil imports from 2006 levels.

Other expert bodies are equally bullish about the prospects of shale oil. The International Energy Agency forecasts that by 2017 the U.S. will overtake both Russia and Saudi Arabia to become the world’s biggest oil producer, and that by 2035 it will be able to eliminate almost all oil imports, including from Canada. PricewaterhouseCoopers (PwC) believes that U.S. shale oil production could reach four million barrels per day by 2035, more than triple the U.S. government’s official estimates. This has been an overachieving industry, it notes, with a torrid 26% per annum growth rate to date and an estimated 33 billion barrels in the ground, up dramatically from the 2007 estimate of just four billion barrels.

The global prospects — estimates of recoverable shale oil reserves have climbed to as much as 1.5 trillion barrels — change the game again. PwC believes that the gush of oil that the globe will be seeing will dramatically lower oil prices, possibly by US$50 a barrel, boosting the global economy by as much as US$2.7-trillion a year by 2035. The biggest winners of this shale-oil fallout are India and Japan, whose GDP could rise by an extra 7%, followed by the U.S. and the eurozone, which could see extra 5% rises.

But there are also losers. Russia and the Middle East oil exporters “could see a significant worsening of their trade balances by around 4% to 10% of GDP,” PwC says. According to Citigroup, with shale oil added to the world’s existing conventional and tar sands supplies, oil prices could drop below the break-even levels that many countries need. Russia may not be able to balance its budget. The picture for “Venezuela is pretty bleak.” Some countries risk becoming “failed states.”

Put another way, the democracies all win, the dictatorships and authoritarian states mostly lose. Business as usual would end for many of the bad guys. Iran, considered the world’s chief financier of terror, would need to scale back its nefarious activities. Venezuela, which finances anti-American activities throughout Latin America, would likewise be curbed. Saudi Arabia might not be able to finance the vast complex of mosques and madrasas — many thought to have radicalized terrorists — that it supports in Pakistan and in the West. These would be welcome restraints — according to a Gallup poll released this week, 96% of Americans consider preventing international terrorism to be their top foreign policy goals. With almost equal passion, Americans desire to be secure in energy.

None of the benefits to the West of abundant energy supplies and low energy costs — whether in curbing terrorism, feeling energy secure or spurring economic prosperity — are cast in stone, however. If governments intercede with climate-change regulations the coming oil revolution could be snuffed out in its infancy, notes an HSBC study. The U.S. administration wants an atmosphere limited to a carbon concentration of 450 parts per-million, an amount that would allow only one-third of the world’s current proven reserves to be burned. Numerous oil projects — those being developed at more than US$50 a barrel — might well be cancelled. All told, HSBC warns, oil and gas majors could lose up to 60% of their market value — their reserves would become “unburnable” — in a low-carbon world.

Because HSBC sees the low-carbon scenario as credible, it advises its clients to be wary. “In our view, investors should focus primarily on companies with low-cost future projects,” it states. “Capital-intensive, high-cost projects, such as heavy oil and oil sands, are most at risk under our scenario.” PwC and Citigroup also note that their projections would be affected by environmental factors, as does OPEC in its February report. As do environmentalists, who are doing their utmost to lobby for a low-carbon world. Says Post Carbon Institute’s David Hughes, author of a study released this week of shale and other energy technologies, “the projections by pundits and some government agencies that these technologies can provide endless growth heralding a new era of ‘energy independence,’ in which the U.S. will become a substantial net exporter of energy, are entirely unwarranted based on the fundamentals … these exuberant forecasts will prove to be extremely difficult or impossible to achieve.”

To date, those forecasts are being achieved — in fact they’re being exceeded. Because curbs on fossil fuels and government-funded renewable energy projects have proven to be ruinously expensive, and because the doomsayers’ projections consistently fail to materialize — the chairman of the United Nations IPCC this week acknowledged that global temperatures have been at a standstill for 17 years — the broad public has balked at sacrificing the economy for dubious environmental benefits. That balk will only become stouter as the public realizes that climate-change regulations thwart both its desire to be energy secure and to fend off terrorist attacks.

Worldwide shale oil production could add $2.7-trillion to the global economy annually by 2035 by slashing the price of crude by as much as $50 a barrel, PwC said on Thursday.

Shale oil production could surge to 14 million barrels per day, or as much as 12 percent of total oil output from around 1 percent now, as it expands from its U.S. base over the next two decades, the world’s largest accounting firm said in a report.

That could lift global gross domestic product by between 2.3% and 3.7% per year by 2035, according to the report, “Shale oil: the next energy revolution”.

“Lower global oil prices due to increased shale oil supply could have a major impact on the future evolution of the world economy by allowing more output to be produced at the same cost,” John Hawksworth, chief economist at PwC and co-author of the report, said.

Bigger flows of shale oil will not increase overall consumption substantially, because demand is not heavily dependent on price, but it will cut the cost of fuel, Adam Lyons, director of PwC’s oil and gas strategy team, said.

“One effect will be to cut the need for expensive, environmentally destructive extraction techniques like the Arctic and tar sands,” he added.

The rapid growth in shale oil has not been factored into price projections by the two major international oil agencies – the U.S. Energy Information Administration (EIA) and Paris-based International Energy Agency, the report said.

Current global oil demand amounts to 80-90 million barrels per day (bpd), and the agencies estimate it will increase to around 110 million bpd by 2035.

“Their projections … are arguably conservative as they are based only on resources about which there is already a high degree of certainty,” the report said.

“Past experience of shale oil and shale gas suggests that these resource estimates are likely to be revised upwards significantly over time.”

PRICE DROP

If the Organization of Petroleum Exporting Countries cuts production in response to the extra supply, oil prices will fall to around $100 per barrel in today’s money by 2035, the report said.

If OPEC does not cut production, oil could fall to around $83 per barrel in today’s money by 2035, PwC estimated, or $50 less than the EIA’s 2035 real-terms forecast price of $133.

The level of support will vary greatly, however, from country to country, it said.

“Large net oil importers such as India and Japan may see their GDP boosted by around 4 to 7% by 2035 in our alternative scenarios, while the U.S., China, Germany and the UK might gain by around 2 to 5 percent of GDP,” Hawksworth said.

On the eastern bank of the Mississippi River, about an hour upstream from New Orleans, the outline of Nucor Corp.’s new US$750-million iron-processing plant is rising between fields of sugar cane and sweet gum trees.

Surveying the facility from the road, Michael Eades, president of Ascension Economic Development Corp., says it’s part of a wave of investment lured by low natural gas prices to this stretch of Louisiana’s industrial riverfront. Companies such as Westlake Chemical Corp., Potash Corp. of Saskatchewan Inc. and Methanex Corp. have projects in the works. Ormet Corp. reopened an alumina refinery last year, bringing back 250 jobs.

“We’re just seeing an incredible amount of activity,” said Eades, who tallied US$1.1-billion in new projects last year in Ascension Parish alone, where his private, nonprofit group promotes development. He expects twice that this year.

It’s a harbinger of a nationwide investment boom spreading from the oil fields of North Dakota and the Marcellus gas shale in Pennsylvania to power plants in California and chemical refiners in Texas. A surge in U.S. natural gas development has spurred US$226-billion in spending plans on pipelines, storage, processing facilities and power plants, most slated for the next five years, according to Industrial Info Resources, a market- intelligence provider in Sugar Land, Texas.

U.S. energy supplies have been transformed in less than a decade, driven by advances in technology, and the economic implications are only beginning to be understood. U.S. natural gas production will expand to a record this year and oil output swelled in July to its highest point since 1999. Citigroup Inc. estimated in a March report that a “reindustrialization” of America could add as many as 3.6 million jobs by 2020 and increase the gross domestic product by as much as 3%.

Narrow Gains

So far, the economic benefits have been confined to states such as Louisiana, Texas and North Dakota, while the national jobless rate has stayed above 8% for 42 straight months in the wake of the worst recession in seven decades.

“It is definitely a positive for the economy, but one can overstate how much of a positive,” said Michael Feroli, chief U.S. economist for JPMorgan Chase & Co. Oil and gas production account for about 1 percent of gross domestic product, and will have a limited impact on the country’s unemployment, he said.

Even so, there are signs the economic gains have begun to expand beyond the oil and gas fields and that the promise of abundant, low-cost fuels will give a competitive edge to industries from steel, aluminum and automobiles to fertilizers and chemicals.

Jobs Debate

That would provide a boost to a U.S. manufacturing sector that has lost 5.12 million jobs since 2001 and become the focus of a national debate over how to revive factory employment. Manufacturers have added 532,000 jobs since January 2010 as the economy started to recover, Bureau of Labor Statistics data show.

The expansion of fossil-fuel production — coupled with a weak economy and increased energy efficiency — has helped the U.S. pare its crude oil imports by 17 percent since the 2005 peak, Energy Department data show. Imports in 2011 accounted for 45 percent of U.S. consumption of crude and refined products. The department predicts the share will fall to 39 percent next year, which would be the first time since 1991 that imports dropped below 40 percent of demand.

“The impact on the global petroleum market and the natural gas markets is really palpable and wildly underestimated,” said Ed Morse, head of commodities research at Citigroup Global Markets Inc. who led the team that wrote the March report. The economic activity that comes with higher energy production will boost incomes, increase consumption and create wealth, he said.

Cheaper Energy

Increased production and swelling domestic stockpiles have helped make U.S. energy cheaper than in other countries. U.S. oil futures have slid to a $20 a barrel discount to London- traded Brent, a benchmark for more than half the world’s oil. Natural gas in the U.S. fell to $1.902 per million British thermal units in April, the lowest in a decade. The fuel costs almost three times as much in the U.K. and more than five times as much in Japan.

“This is one of those rare opportunities that every country looks for and few ever get,” said Philip Verleger, a former director of the office of energy policy at the U.S. Treasury Department and founder of PKVerleger LLC, a consulting firm in Carbondale, Colorado. “This abundance of energy gives us an opportunity to rebuild our economy.”

Cycle of Growth

Verleger envisages a virtuous cycle of economic growth as producers, flush with cash from oil and gas sales, will buy more equipment and put more people to work, while low-cost energy puts cash back in consumers’ pockets, stimulating spending.

Companies plan to invest $138 billion in more than 700 natural gas storage, pipeline and processing plants in the U.S., and another $88 billion in more than 500 gas-fired power generation units, according to Joseph Govreau, vice president and editor-in-chief of Industrial Info Resources. The firm tracks projects from planning stages through construction.

The IIR estimates don’t include petrochemical and fertilizer projects, which are undergoing a revival because of the low cost of natural gas feedstock.

Cairo-based Orascom Construction Industries is investing $250 million restarting an ammonia and methanol plant in Beaumont, Texas. Another Orascom subsidiary may build a $1.3 billion fertilizer plant in Iowa that would create as many as 2,000 construction jobs and 165 permanent positions, according to Tina Hoffman, a spokeswoman for the Iowa Economic Development Authority.

‘Massive’ Investment

“The amount of petrochemical investment that the U.S. will have in the next 10 to 15 years is massive,” said Omar Darwazah, head of investor relations for Orascom. “Given the shale gas boom, gas prices in the U.S. are arguably more competitive than the Middle East, because you don’t have the political risk.”

Increased U.S. production has already wrought significant shifts across the energy industry. Plans for gas-import terminals, thought indispensable five years ago, have been shelved in favor of export facilities such as Cheniere Energy Inc.’s $10 billion plant in Louisiana’s Sabine Pass.

Enterprise Product Partners LP and Enbridge Inc. this year reversed the Seaway pipeline that once carried oil imports from the Gulf Coast to a storage hub in Oklahoma. Now, it carries crude produced in states such as North Dakota and Colorado to refiners in Texas and Louisiana, which process and, increasingly, export it. East Coast refiners, dependent on more expensive tankers of foreign crude, are working to develop rail links and pipelines to bring oil east.

Environmental Concern

Environmentalists say cheap fossil fuels come with a high price, including air pollution that can cause respiratory difficulties, and drinking water contamination from hydrofracturing, or fracking, in which a high-pressure stream of fluid is shot underground to crack rock and release hydrocarbons. Lower gas and oil costs have also undermined investment in power sources that produce less carbon dioxide, including wind, solar and nuclear, raising concern that climate change will accelerate.

“The state is just overjoyed at all the jobs that will be coming to Louisiana without looking at the health side effects and environmental side effects,” said Darryl Malek-Wiley, a community organizer at the Sierra Club in New Orleans.

The report from Citigroup — “North America, the New Middle East?” — estimated that the U.S. could become the world’s largest producer of crude and natural gas liquids such as propane by 2020, overtaking Russia and Saudi Arabia.

China Consumption

U.S. natural gas prices may eventually rise if planned export terminals increase demand for the fuel, putting domestic consumers in competition with foreign markets willing to pay more. China will drive global gas consumption higher by 2.7 percent a year through 2017, the International Energy Agency said in a June report. The U.S. already competes with global consumers for refined products such as gasoline and diesel.

Still, the promised bounty from lower prices can be seen along the highways and back roads of Ascension Parish, in the heart of Louisiana’s plantation country.

In November, cheap natural gas prices convinced Hannibal, Ohio-based Ormet to reopen the refinery that makes alumina, used in aluminum production. The facility was shuttered in 2006, said Chief Financial Officer James Riley.

In nearby St. James Parish, Nucor has begun construction on the plant that will process iron using natural gas. The product will supply its steel mills, said Katherine Miller, a spokeswoman for Charlotte, North Carolina-based Nucor. Five hundred people will be needed to build the plant and 150 will be employed there once completed, she said.

Doubling Workforce

Eades gestures toward construction trailers parked on the site where Vancouver-based Methanex said in July that it will reconstruct a plant moved from Chile, white, football field- sized domes that will store Nucor’s iron ore, and chutes that carry bauxite over the Mississippi River levy into Ormet’s rust- colored plant.

All this construction means new jobs. MMR Group, a Baton Rouge-based industry contractor, will double its workforce of 2,800 in the next two years, said Grady Saucier, vice president of marketing.

A five-minute drive from MMR’s offices in Ascension Parish, Associated Builders & Contractors, a trade group, can’t keep up with demand for its training program for would-be electricians, pipefitters and welders. Steven Allen graduated from the school’s pipefitting certification program this year. Now, he earns as much as $28 an hour working in petrochemical plants, up from the $9 an hour he made as a construction laborer.

Family Struggle

“Being a laborer and a helper isn’t going to cut it when you’ve got a family to support,” said Allen, 30, a father of 6- year-old twins.

Smaller businesses, including valve manufacturers, electric-motor companies and rental lots packed with heavy equipment, also feed off the boom, Eades says. One company, Rain for Rent, provides fake downpours seen on movie sets — as well as storage tanks and water pumps to the petrochemical industry.

Closer to Interstate 10, which connects New Orleans to Baton Rouge, a TownePlace Suites by Marriott and a Holiday Inn Express have opened in the past year next to an outlet mall and a Cabela’s outfitters store, all benefiting from the influx of new workers to the region, Eades said.

“If you have gas prices in the U.S. that are substantially cheaper than Europe or Asia, it has to have a substantial impact,” said James Brick, an analyst in Houston with Wood Mackenzie, an energy and metals researcher. “The question we’re now asking is, ‘Is this the tip of the iceberg?’”

It’s tough to get a word in edgewise as U.S. producers beat their chest over their shale oil and gas finds and impending energy independence, but one analyst has managed to deflate some of the hype.

Bob Brackett, an analyst at New York-based Bernstein Research, says oil wells in Montana, part of the giant Bakken shale basin, are rapidly deteriorating.

“Something is rotten in the State of Montana and it smells like moldy shale,” Mr. Brackett wrote in a note to clients. “Montana production of oil is down 38% from its 2006 peak of more than 100,000 barrels per day.”

The state, which shares the Bakken with North Dakota and Saskatchewan, produces between 1% and 2% of U.S. output and is home to two of the largest oil fields in the country. More important, Montana is home to Elm Coulee field, the poster child of Bakken potential and was expected to recover more than 200 million barrels.

But Montana’s oil boom cycle appears to have flamed out pretty quickly. As a result, Montana’s economy, which outpaced the U.S. economy during the mid-2000s, is expected to post just 0.9% growth this year, according to JPMorgan Chase & Co. estimates. Unemployment stands at 6.9%, nearly double that of neighbouring North Dakota, where the oil boom has shifted.

The fear is, will Montana’s rapid boom-to-bust cycle be replicated elsewhere in other U.S. shale basins?

While Mr. Brackett concedes that Montana production is roughly 10% of North Dakota’s overall output, the decline “contradicts the industry canard that shale oil production growth is seemingly limitless,” he said.

Crucially, Montana output is declining not because of oil prices or fewer drilling permits, but as resource plays have limited or finite drilling locations, the best locations get drilled early, the less economic ones later, and once they are drilled, operators move on, the analyst argued.

Occidental Petroleum Corp., which bet early on a domestic production surge in the basin, is already pulling back.

“We got a lot better places to put money right now than the Bakken — that’s why I am slowing it down,” Occidental chief executive Stephen Chazen said on a first-quarter conference call with analysts — a position he reiterated at the end of the current quarter.

Montana shale production has fallen from a peak of 400 oil-equivalent barrels per day per well during 2003-05 to about 250 per well today, even though companies had poured in massive resources and employed the latest technologies and techniques during this time to extract more from each well.

Another worrying indicator for oil shale developers is how quickly a high-oil producing well is downgraded to a ‘stripper’ well — industry jargon for a less-productive well. Bernstein research shows that it takes a Bakken well an average of six years to become a stripper well, which suggest the issue is not just restricted to Montana wells.

“There are 200 modern Bakken horizontal wells that are now strippers. In six years there will be 4,000 Bakken horizontal wells that are strippers,” said Mr. Brackett, citing the example of the 800-well Richmond County that began operation in 2000, peaked around 2006 and has been steadily declining since. “One quarter of the expected volume of a Bakken well will be delivered during its time as a stripper and, in that time, the price of oil must exceed the operating costs of these old wells.”

Costs are going to be crucial as oil prices recede. Oil field services already moan of high costs of raw materials such as guar gum, apart from rising labour costs. While drilling costs are coming down, a rapid rise in production could see oil prices go the way of natural gas prices, which recently touched a decade low.

While West Texas Intermediate prices stand at US$91 per barrel, they had slipped to US$77.91 as recently as June, uncomfortably close to the US$55-US$70-per-barrel breakeven cost for a barrel of U.S. shale oil.

Meanwhile, the International Energy Agency says Bakken’s enormous growth rate in 2012 will abate somewhat in 2013 as “geography and bottlenecks will crimp producer netbacks.”

But for now, the U.S. oil industry remains a feel-good story for a country looking for positive news in times of an alarming debt crisis and political inaction. The U.S. Energy Information Administration (EIA) latest estimates show the country’s proven oil and gas reserves rose by the highest amount since it began publishing proved reserves estimates in 1977. Crude oil reserves have shot up 13%, with all the key areas — Texas, Gulf of Mexico, Alaska, California and North Dakota — posting impressive growth. Meanwhile, four of the five largest natural-gas states (Texas, Louisiana, Oklahoma and Colorado) registered net gains, leading to an overall 13% rise in gas reserves.

The EIA credits the use of horizontal drilling and hydraulic fracturing in shale and other tight formations for driving estimates upward.

While there is no denying the long-term prospects for the United States’ oil-and-gas industry, energy independence may remain a distant dream.

“Even under a high potential [domestic production] scenario, the United States will still need to import oil for the foreseeable future,” says the National Petroleum Council, an advisory body, which should be music to the ears of Canadian oil sands producers watching the U.S. shale revolution with dismay.

But they shouldn’t get overexuberant, as the worrying Montana shale data may not mean an imminent collapse in shale production.

“While U.S. oil production will grow over the next few years with the Bakken and Eagle Ford becoming million-barrels-a-day fields, the world will not find itself awash in oil (shale or otherwise),” Mr. Brackett said.

You can say many things about the oil and gas industry, but you can’t argue with its sheer ability to create jobs and stimulate economic growth.

This was yet again underscored in a recent report which shows how cities drenched in oil and gas development led U.S. economic growth last year.

Lafayette (Louisiana), Odessa (Texas) and Bismarck (North Dakota) will each see robust activity in natural resources and posted growth upwards of 7%, says IHS Global Insight in a survey of U.S. cities.

“The Bakken shale oil formation (an oilfield stretching from Canada to North Dakota and Montana, and containing possibly 4 billion barrels of oil reserves) will provide a surge in real GMP [Growth Metro Development] to Bismarck, while the energy sectors in Odessa (the long time beneficiary of the Permian Basin) and Lafayette will also drive employment growth and real GMP gains while lowering unemployment,” IHS said.

Gains in the energy and manufacturing sectors will also benefit industrial cities like Sandusky (Ohio) and Holland-Grand Haven (Michigan), and oil and natural gas areas like Fargo (North Dakota), Corpus Christi and Midland (Texas). They are all anticipated to fall within the top fifteen metros in terms of real GMP growth this year, the energy consultancy reported.

The energy sector also boosted related sectors such as the chemicals industry.

“The industry surge this decade in investment, jobs, and incomes has been largely spurred by low natural gas prices, a result of the rapid incorporation of new drilling techniques to extract shale and other unconventional gas supplies in the U.S.,” notes IHS.

And the new gas fields have spurred investment not only in the Gulf of Mexico region, but across the U.S. For instance, a petrochemical processing, “Cracker,” plant is to be constructed in the Pittsburgh metro owing to its proximity to shale gas supplies.”

Chicago narrowly leads Houston with 43,000 jobs, led by its plastic products manufacturers. Twenty eight metros have employment in excess of 10,000 in this sector, and 206 metros employ more than 1,000 in the chemicals and plastics industries. Notably fast growth occurred in 2011 in Minneapolis, Dallas, San Diego, and Milwaukee among large metros, and in Muskegon, Greeley, Spokane, Gadsden, and Warren.

Here are the Ten Oil Boomtowns Of 2011:

#1 MIDLAND, TX (2011 GMP Growth= 9.1%, 2012 Forecast= 5.5%)
The onetime home of oil industry aficionado George W. Bush, was the United States’ fastest growing city, according to IHS Global Insight. The city’s unemployment rates stands at 3.5%, less than half of the country’s average rate.

#2 ODESSA, TEXAS (2011 GMP Growth: 9%, 2012 Forecast= 9.7%)
Fellow Texan city Odessa emerged as the second fastest-growing city in the United States, with enviably low unemployment rates. The city’s real GDP growth could well hit 9.7% in 2012, according to IHS.

Mark Sterkel/AP PhotoA taxidermist in downtown Odessa, Texas blows the dust off a Musk Ox that he and his crew were cleaning for a private collector.

#3 PASCAGOULA, MISSISSIPPI (2011 GMP Growth: 9%, 2012 Forecast= 0.8%)
Chevron’s massive refinery helped ease the pain for the city and the wider Mississippi state which is reeling from a 12% unemployment rate. Manufacturing and port facilities also helped an otherwise poor economic outlook for the city.

# 4 CASPER, WYOMING (2011 GNP Growth: 8.8%, 2012 Forecast= 3.6%)
The ‘Oil City’ is the original oil boomtown. The city first got its taste of hydrocarbon dependency back in 1889 with the discovery of the Salt Creek Oil Field and has never looked back since. A Sinclair Refinery is among the oil installations continuing the tradition.

Courtesy/Tara CrookerStarting operations as White Eagle Refinery in 1923, the Casper Refinery remains one of the oldest refineries still operating in the Rocky Mountains today.

# 5 LAFAYETTE, LOUISIANA (2011 GMP Growth: 7.2%, 2012 Forecast= 7.5%)
Historically, the oil & gas industry has been a catalyst for growth in Lafayette, initiating technological advancements and increasing the skill levels of much of Lafayette’s workforce, notes a report on the Louisiana city. Baker Hughes, Schlumberger and Halliburton — three of the biggest oilfield services giants – are some of the largest employers in the city. Oil rig counts have been steadily rising in Lafayette as State strengthens its position as the nation’s fourth-largest oil producer.

REUTERS/Lee Celano/FilesOil rigs sit in the Gulf of Mexico near Port Fourchon, Louisiana

Courtesy Three Penny Productions.Haynesville's shale riches inspired the movie Haynesville: A Nation’s Hunt for Energy, which takes place in the Louisiana backwoods, and follows the momentous discovery of the largest natural gas field in the U.S.

# 7 BAKERSFIELD-DELANO, CALIFORNIA (2011 GMP Growth: 7%, 2012 Forecast= 4.1%)
Bakersfield and the wider Kern County account for approximately 75% of California’s in-state oil and about 58% of the state’s total natural gas output, according to the local chamber of commerce. The area also benefits from strong agriculture production.

Ken James/BloombergOil pumps stand at the Chevron Corp. Kern River oil field in Bakersfield, California.

# 8 BATON ROUGE, LOUISIANA (2011 GMP Growth: 6.9%, 2012 Forecast= 1.5%)
The Wikipedia entry says it all: Baton Rouge’s largest industry is petrochemical production and manufacturing. The ExxonMobil facility in Baton Rouge is the second-largest oil refinery in the country; it is among the world’s 10 largest. Baton Rouge also has rail, highway, pipeline, and deep water access. Enough said.

F. Carter Smith/Bloomberg NewsA refinery Baton Rouge, Louisiana.

# 9 LAKE CHARLES, LOUISIANA (2011 GMP Growth: 6.9%, 2012 Forecast= -0.9%)
The Port of Lake Charles is an important oil and gas supply hub and the 10th busiest port in the U.S. Calcasieu Refining Company, Citgo and Phillips66 (formerly ConocoPhillips) have operations in the city. Plus, Leucadia Energy is building a $1.6-billion plus coke gasification facility.

Julia Schmalz/BloombergTube segments sit after an explosion that created cracks in the shale thousands of feet below the surface so that water and sand can be pumped into the well at high pressure, creating an opening for the natural gas during fracture stimulation.

#10 BIMARCK, NORTH DAKOTA ND (2011 GMP Growth, 6.8%, 2012 Forecast=7.3%)
The Bakken shale reserves has transformed the fortunes of North Dakota and the state capital Bismarck. The Peace Garden State, which shares the Bakken with Manitoba and Saskatchewan, has seen its oil production quadruple since 2005 and unemployment drop to 3.8%, in sharp contrast to the national average of 8.2%.

Daniel Acker/BloombergA series of pipes direct natural gas at a Williston Basin Interstate Pipeline Co., a subsidiary of MDU Resources Group Inc., compression station in Bismarck, North Dakota.

Canadian energy firms will be given a fair shot at helping Israel develop its vast deposits of newly discovered shale oil and gas resources, assures the Jewish state’s Ambassador to Canada. Miriam Ziv spoke with the Financial Post’s Jameson Berkow about how the long-standing Canada-Israel relationship can be leveraged and expanded to help Israel achieve energy independence and what is becoming of resources discovered in the Palestinian territories. The following is an edited transcription of their conversation.

Q: The Shfela Basin southwest of Jerusalem has been estimated to contain as many as 250 billion barrels of shale oil. What does a discovery of such magnitude mean for Israel?
A: Until not long ago, we had assumed that somehow we were ignored when God shared the oil and gas in the region and that he forgot about us, that we were the land of just milk and honey. But first of all we shouldn’t jump the gun. We did have discoveries but we still have some time until we start concrete production. There are many elements that will be changed once we start pulling the gas out of the shale. This is, for all of us, a novelty, even I am still struggling to understand better exactly what the prospects are, where we are going, but it is not something that we will have to answer tomorrow. We will be self-reliant. We will not have to reply on others and that is very important for us. But first we shouldn’t jump the gun, we did have discoveries but we still have some time until we start concrete production.

Q: How can Canada help?
A: We never had any resources before, we never had any discoveries so I’m not sure we have enough engineers or experts in these areas so to get some more advice from Canada and maybe some scholars or even have students come and study here and learn more about it [would help]. There are many elements that will be changed once we start pulling the gas out of the shale, but it is a process and this is where the Canadian knowhow and hopefully also Canadian companies can share, join in and hopefully work with us.

Q: Will that involve an expansion of the Canada-Israel Free Trade Agreement that has been in place since 1997 but does not cover the transfer of labour and services?
A: We have now started the process of upgrading or modernizing the agreement because this is a first-generation agreement that we have now. There is a clear interest from both governments to have closer ties that not only express the people-to-people aspect but also some institutional official arrangements and agreements. We are looking into various areas where we can work more closely together.

Q: Is there a timeline in place for when the process will lead to practical changes to the agreement?A: We are only at the beginning of the process so it is very difficult to say because I assume that once the negotiators both start talking there will be some issues to overcome or others.

Q: In the meantime, do Canadian companies have cause for concern that their interest will be trumped by U.S. firms due to the United States long being Israel’s closest ally?A: The decision will be made according to the expertise proposed as this is a free market, not a competition. Companies who are the best and will be abel to respond better to Israel’s needs will be the ones who will go in. So I don’t see it as any competition, we don’t measure friendship. I think both countries — Canada and the U.S. are our best friends today — help us out in the international arena so I wouldn’t even try to measure our friendship. But the same goes for business. These are the laws of the free market. We are all democracies and we all allow decision making to be done by the business companies and they will be the ones to decide where to go.

Q: Some of the offshore gas reserves have been discovered off the coast of the Gaza strip. Who owns those?A: There are clear boundaries in a sense, part of the gas reservoirs are on the Gazan shore and it is theirs [the Palestinians]. They are exploring it. There are British companies working there and doing the exploration. We are not exploring the reserves [the Palestinians] have; it is theirs, though a lot has to be happening for us to be able to collaborate. When I dealt with the Palestinians [in one of my former roles] and we were talking about collaboration and working together and then things collapsed so I am very hopeful that it will happen and will happen soon but it is a process that depends a lot on the Palestinians and their interest and will to get into negotiations and they have shown no will or interest there.

The two countries signed an agreement on energy cooperation Tuesday that will allow for more collaboration over resource development projects and renewable power research. Joe Oliver, Canada’s Minister of Natural Resources, signed the agreement along with Israeli Energy and Water Resources Minister Uzi Landau in Tel Aviv.

Ahead of a news conference planned for Thursday, Mr. Oliver said in a statement there was “tremendous opportunities for Canada and Israel to cooperate more closely on energy issues.”

As reported in the Financial Post last week, Mr. Oliver flew to the Jewish state on Friday to discuss how Canada could help the country develop its recently discovered massive unconventional oil and gas deposits. Last year Israel discovered shale oil deposits that are believed to be among the largest in the world.

“Large underground oil shale formations have been discovered in Israel, its vast potential is currently being explored, and grounds are being prepared for an expansion of activities,” notes an excerpt from Tuesday’s agreement.

The London-based World Energy Council estimates the Shfela Basin, southwest of Jerusalem, contains up to 250 billion barrels of shale oil. The resource places the country third globally in shale oil resources, behind just the United States and China, and rivals the 250 billion barrels of conventional oil reserves controlled by Saudi Arabia.

Offshore, the country is said to possess more than 16 trillion cubic feet of unconventional natural gas deposits. Those discoveries have marked a dramatic turnaround for Israel’s energy fortunes, as decades of previous exploration had proven fruitless.

A 1997 free trade agreement between Canada and Israel excludes areas such as professional services and financial investment. It is unclear whether this new agreement would effectively expand free trade access to those areas.

Paul Duchesne, a spokesperson for Natural Resources Canada, said the agreement “builds on 15 years of strong commercial relations under the FTA,” adding the department hopes it will “further increase bilateral trade in the energy sector.” However, he did not say whether those increases would come as a result of any expansions to free trade.

Collaboration between the two countries on development issues actually began years before the formal free trade agreement came into force. The Ottawa-based Canada-Israel Industrial Research and Development Foundation was established in 1994 to help firms in both countries establish research and development partnerships and continues to foster bilateral sharing resources and expertise.

Henri Rothschild, president of the foundation, said the agreement will make his job easier simply by increasing awareness of Canada’s attractiveness to other global markets.

“Global technology partnerships are going to become more and more important in the years ahead and as countries like Brazil, Turkey and China build global networks and look for partners; most other countries love to partner with Canada we just don’t appreciate enough the opportunity that we have for building bridges outside of this country,” Mr. Rothschild said.

“So the agreement signed by Minister Oliver is a very good thing for Canada and creates visibility for opportunities in other countries.”

While Canada is a noted world leader in shale extraction technology, Israel also has a renowned reputation for innovation and the country is already contributing to the development of Canada’s oil sands. The upgrader technology that has been online at the Long Lake project site in northern Alberta since 2009 was developed by Israel’s Ormat Industries.

Israel has little experience with natural resource development, particularly with the capital and technologically intensive process of extracting shale oil and gas. But the sector has been thriving in Canada for decades and Mr. Oliver believes Canadian knowledge and expertise could help Israel more quickly attain energy independence.

CALGARY • Canada is looking to strengthen energy ties with Israel in a move that could help the Jewish state alter the balance of oil power in the Middle East.

Natural Resources Minister Joe Oliver left for the country on Friday. His trip will be focused on pitching Canada to his counterparts in government, oil company executives and leading academics as an ideal partner to help Israel develop its newly discovered bounty of unconventional oil and gas.

“Our presence in energy there, it creates a potential that did not exist before,” Mr. Oliver said in an interview.

‘Our presence in energy there, it creates a potential that did not exist before’

Since its founding six decades ago, multiple failed exploration attempts have led many to conclude the country, just a third larger than Prince Edward Island, was devoid of any significant energy resources.

But the discovery last year of a field 30 kilometres southwest of Jerusalem estimated by the London-based World Energy Council to contain up to 250 billion barrels of shale oil, together with 16 trillion cubic feet of natural gas found offshore, have suddenly put Israel’s name on the energy map. The oil find rivals global oil superpower Saudi Arabia’s 260 billion barrels in proven conventional reserves and was publicly dubbed “the equivalent of Saudi extra-light” by Harold Vinegar, former chief scientist for Royal Dutch Shell.

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At minimum, it could mean energy independence for Israel. The country currently imports nearly its entire oil supply mostly from Russia and the former Soviet bloc. Several times throughout history and as recently as the 2006 Hezbollah conflict, those supplies have been blocked off, spawning fuel shortages.

“For them, obviously energy security is a critical strategic issue. I think it is for every country, but for them in particular,” Mr. Oliver said. “There has been talk, and this isn’t a prediction, but there has been discussions of them maybe even being an exporter.”
Canada, meanwhile, has led the development of shale technology, a costly and complex process.

“There are Canadian companies, Canadian science and technology which might be able to be helpful to them,” Mr. Oliver said.

Michael Byers, a political science professor at the University of British Columbia who holds the Canada Research Chair in global politics, said the impact to the region would have been far more dramatic had Israel discovered those resources 40 years ago.

Today, “the most significant impact will be in Israel’s comfort level, [but] that is a significant factor in a dangerous and unpredictable part of the world,” Mr. Byers said.

A free trade agreement has been in place between Canada and Israel since 1997, though despite subsequent expansions it still lacks provisions for the transfer of services, investment or government procurement. Ottawa first announced plans to “modernize” the agreement in 2010 and Mr. Oliver stressed time is of the essence.

“In some cases there are contracts that are going to be signed or are being signed as we speak that could leave us out of markets,” he said, adding the global energy picture in 10 years is “going to look very different and we need to stay ahead of the curve.”

“If we are nimble we could get there in time.”

Bob Schulz, professor of petroleum land management at the University of Calgary’s Haskayne School of Business, said the possibility of Canadian technology and investment going to Israel “would certainly change the [political] dynamics of the Middle East,” in that energy revenue would give it the means to finance much of its own defence instead of continuing to rely heavily on Western support.

If the plan is to maximize output, then Mr. Schulz said Canada’s energy producers could face even lower oil prices as a result of the jump in global supply.

“If I were a producer I’d want to talk to the minister when he got back and try to figure out what Israel’s plans are,” he said.

With the environmental debate over shale raging in Israel just as hard as it is here, those plans may require more than one state visit to learn.